Embodiments disclosed herein relate generally to methods and apparatus for controlling well influx within a wellbore. In particular, embodiments disclosed herein relate to methods to design and assemble well influx control systems.
During the past years, with the increase in price of fossil fuels, the interest in developing new production fields has dramatically increased. However, the availability of land-based production fields is limited. Thus, the industry has now extended drilling to offshore locations, which appear to hold a vast amount of fossil fuel.
A traditional offshore oil and gas installation 10, as illustrated in FIG. 1, includes a platform 20 (of any other type of vessel at the water surface) connected via a riser 30 to a wellhead 40 on the seabed 50. It is noted that the elements shown in FIG. 1 are not drawn to scale and no dimensions should be inferred from relative sizes and distances illustrated in FIG. 1.
Inside the riser 30, as shown in the cross-section view, there is a drill string 32 at the end of which a drill bit (not shown) is rotated to extend the subsea well through layers below the seabed 50. Mud is circulated from a mud tank (not shown) on the drilling platform 20 through the drill string 32 to the drill bit, and returned to the drilling platform 20 through an annular space 34 between the drill string 32 and a casing 36 of the riser 30. The mud maintains a hydrostatic pressure to counter-balancing the pressure of fluids coming out of the well and cools the drill bit while also carrying crushed or cut rock to the surface. At the surface, the mud returning from the well is filtered to remove the rock, and re-circulated.
Offshore oil and gas exploration requires many safety well control devices to be put in place during drilling activities to prevent injury to personnel and destruction of equipment. During oil and gas exploration, the many layers being drilled through may contain trapped fluids or gases at different pressures. To balance these varying pressures, during the drilling process, the pressure in the wellbore is generally adjusted to at least balance the formation pressure. Some of the methods that may be utilized to balance these pressures include, but are not limited to, increasing a density of drilling mud in the wellbore or increasing pump pressure at the surface of the well.
During the drilling process, when a layer is encountered that includes a substantially higher pressure than that of the wellbore, the well may be described as having encountered a “kick”. A kick is commonly detected by monitoring the changes in level of drilling mud which returns from the annulus on the drilling ship as well as well pressure. If the burst is not promptly controlled, the well and the equipment of the installation may be damaged. Blowout preventers (BOPs) are one type of well control device that is often used to close, isolate, and seal a wellbore during a high pressure event or kick. Blowout preventers are typically installed at the surface or on the sea floor in deep water drilling arrangements so that kicks may be adequately controlled and “circulated out” of the system. Blowout preventers operate in a similar manner as large valves that are connected to the wellhead and comprise closure members configured to seal and close the well in order to prevent the release of high-pressure gas or liquids from the well. In addition, choke and kill lines are used to control the kick by adding denser mud. Although there are many types of blowout preventers, the most common are annular blowout preventers and ram-type blowout preventers. In a preferred arrangement, annular blowout preventers are typically located at the top of a blowout preventer stack, with one or two annular preventers positioned above a series of several ram-type preventers.
Referring again to FIG. 1, during drilling, gas, oil or other well fluids at a high pressure may burst from the drilled formations into the riser 30 and may occur at unpredictable moments. In order to protect the well and/or the equipment that may be damaged, a blowout preventer (BOP) stack 60 is located close to the seabed 50. The BOP stack may include a lower BOP stack 62 attached to the wellhead 40, and a Lower Marine Riser Package (“LMRP”) 64, which is attached to a distal end of the riser 30. During drilling, the lower BOP stack 62 and the LMRP 64 are connected.
A plurality of blowout preventers (BOPs) 66 located in the lower BOP stack 62 or in the LMRP 64 are in an open state during normal operation, but may be closed (i.e., switched to a close state) to interrupt a fluid flow through the riser 30 when a “kick” occurs. Electrical cables and/or hydraulic lines 70 transport control signals from the drilling platform 20 to a controller 80, which is located on the BOP stack 60. The controller 80 controls the BOPs 66 to be in the open state or in the closed state, according to signals received from the platform 20 via the electrical cables and/or hydraulic lines 70. The controller 80 also acquires and sends to the platform 20, information related to the current state (open or closed) of the BOPs. The term “controller” used here covers the well-known configuration with two redundant pods.
Traditionally, as described, for example, in U.S. Pat. Nos. 7395,878, 7,562,723, and 7,650,950 (the entire contents of which are incorporated by reference herein), a mud flow output from the well is measured at the surface of the water by sensing device including a float in a mud tank. The mud flow input into the well may be adjusted to maintain a pressure at the bottom of the well within a targeted range or around a desired value, or to compensate for kicks and fluid losses.
In one particular scenario, when a kick is detected based on feedback from the sensing device, drilling is stopped, the blowout preventer valves (internal and external to the drill pipe) are closed and heavier drilling mud is pumped down the well bore through kill lines, while a choke line is used to control the flow. When the kick has been controlled, heavier drilling mud replaces the earlier lighter mud in the drill pipe, the choke and kill lines are closed, the blowout preventers are opened and drilling is resumed. As stated, when a kick is detected, the drilling must be stopped, in part due to the lack of a rotating wellhead. Alternative devices have been proposed that allow for continuation of drilling through the use of a rotating wellhead that must be configured as an additional, separate device assembled as part of the drill string below the drill ship and prior to the commencement of drilling. The rotating wellheads are not configured as an integral part of the BOP stack and require substantial amounts of additional seals to stop the flow of mud through the annulus. In addition, hydrostatic bearings and external lubrication systems are needed to allow for rotation of the drill pipe within the rotating wellhead.
Another problem with the existing methods and devices is the relative long time (e.g., tens of minutes) between a moment when a disturbance of the mud flow occurs at the bottom of the well and when a change of the mud flow is measured at the surface. Even if information indicating a potential disturbance of the mud flow is received from the controller 80 faster, a relative long time passes between when an input mud flow is changed and when this change has a counter-balancing impact at the bottom of the well.
Accordingly, there exists a need for an influx control system that allows for the continuation of drilling activities during the presence of a substantially higher pressure than that of the wellbore. More particularly, there exists a need for an influx control system that eliminates the need to stop drilling during the presence of a potential blowout condition and during regulation of the mud flow to prevent a blowout from occurring. In addition, there exists a need for an influx control system that allows for sensing of the presence of a substantially higher pressure in a manner that allows for a reduction in response time than current technologies.